In recent years, the demand for oil and natural gas has increased. The increase in demand for oil and natural gas is driving the oil and gas industry to produce more oil and natural gas using more cost efficient and effective techniques. Extracting subterranean fluids from depleted oil and gas reservoirs with new means is needed.
Generally, when extracting oil and natural gas from subterranean reservoirs, the skilled artisan must consider the properties of the reservoir, the types of fluids present in the reservoir, and the physical and chemical properties of fluids of the reservoir. Another important factor in enhancing the total recoverable reserves of hydrocarbons and other fluids form depleted reservoirs is related to the reservoir pressure of the fluids trapped in the reservoir. When a wellbore penetrates a reservoir, the reservoir pressure forces the subterranean fluids out of the reservoir into the wellbore and up ward toward the surface as a function of lower pressure at the surface. As fluids flow into the wellbore, the pressure of the reservoir decreases, or as commonly referred to in the industry the reservoir pressure depletes. As such, over a period of time of extraction, the reservoir pressure becomes insufficient to force hydrocarbon fluids from the reservoir into the well. Therefore, there is a need to maintain and/or increase the reservoir pressure in these depleted reservoirs in order to maximize the percentage of hydrocarbon fluids recovered from the reservoir.
A reservoir's ability to produce oil is also a function of the reservoir's drive mechanism. A reservoir's drive mechanism refers to the forces in the reservoir that displace hydrocarbons out of the reservoir into the wellbore and up to surface. Reservoir drive mechanisms include gas drive (gas cap or solution gas drive), water drive (bottom water drive or edge water drive), combination drive, and gravity drainage. An example of solution gas drive is when soluble gases in the oil expand and are carried into the well with liquid hydrocarbons. Reservoirs where soluble gases form a significant portion of the drive mechanism typically have the lowest reservoir primary recovery factors for hydrocarbons. Therefore, there is a need for a method to continually and rapidly replenish the reservoir energy depleted by the extracted soluble gases. This can be done with the injection of fluids that can energize the reservoir and still more desirable is injecting a fluid that is soluble in the reservoir fluid at reservoir pressure and temperature conditions.
Petroleum engineers often refer to the percentage of oil recoverable from a given reservoir versus the oil in place in a reservoir as the “recovery factor.” During primary recovery phase of a wells exploitation, the natural pressure of the reservoir created by the combination of forces like the earths overburden and subsequent compression of the reservoir fluids drives or forces hydrocarbons into the wellbore. However, only about 10 to 30 percent of a reservoir's original hydrocarbons in place are typically produced from the reservoir during the primary recovery phase. After a number of years of producing fluids from reservoirs under primary recovery methods, it becomes necessary to inject fluids from surface into the reservoirs to enhance fluid production from the depleted reservoir. This process is known as Enhanced Oil Recovery (EOR). The purpose of EOR is to increase the recovery of the reservoir fluids.
In general, Enhanced Oil Recovery is divided into two distinct phases, secondary recovery methods and tertiary recovery methods. Secondary recovery methods generally include injecting water or gas to displace oil and driving the hydrocarbon mixture to a production wellbore which results in the enhanced recovery of 20 to 40 percent of the original oil in place. After a reservoir has been flooded with water or other secondary recovery methods, tertiary recovery methods are used to increase the fluid recovery from the reservoir. However in some cases, tertiary recovery methods may be used immediately after the primary recovery method.
Generally, tertiary recovery methods include steam, gas injection, and chemical injection. Steam enhanced tertiary recovery involves injecting steam down an injection well to lower the viscosity of the hydrocarbon fluid. That is, heavy viscous oil reserves is made less viscous to improve their ability to flow out of the reservoir into a well. Gas injection tertiary methods employ gases such as natural gas, nitrogen, or carbon dioxide that expand in a reservoir to push additional oil to a production wellbore. In all these gas injection means, the fluids are at temperatures of more than −100° F. Fluids that are at a temperature below −100° F. are commonly referred to as cryogenic fluids. Preferred gases are those that dissolve in the reservoir hydrocarbon, which lower the in-situ hydrocarbons viscosity and improve the hydrocarbons flow rate from the reservoir to the well bore. Chemical injection involves the use of polymers to increase the effectiveness of water floods, or the use of detergent-like surfactants to reduce the surface tension that often prevents oil droplets from moving through a reservoir.
Generally, carbon dioxide is a common miscible tertiary EOR fluid. Carbon dioxide is the preferred EOR fluid in the current art because it can be delivered to wellbores in a liquid form above cryogenic temperatures. For example, carbon dioxide has a boiling point of −70° F. at ambient pressures, while other gases have a higher boiling point, e.g., methane has a boiling point of −259° F. at ambient pressures. The difference between these boiling points shows that carbon dioxide requires less energy to condense to a liquid phase in comparison to most other fluids that are miscible in hydrocarbon liquids. Nevertheless, over fifty percent of the cost when using carbon dioxide to flood the well is the initial purchase of the carbon dioxide. Further, the use of carbon dioxide in EOR methods has other disadvantages. For example, once carbon dioxide is injected into an injection well, it cannot be recovered and resold. Also, it is a greenhouse gas, the release of which into the atmosphere will likely be regulated. Moreover, it causes formation of carbonic acid in water that can lead to corrosions of pipes and other equipment. What is needed is a tertiary fluid that is soluble in the hydrocarbon fluids, can be commercialized as a part of the reservoir fluid recovery process, and is non-corrosive.
On the other hand, it is plausible for liquid methane or liquid natural gas, LNG, to be used to flood the reservoir in tertiary recovery methods if the liquefied natural gas supply can be replenished continually. When liquid natural gas (LNG) is used as a cryogenic flood fluid to enhance oil recovery, the LNG may be re-gasified under ground and separated from the tertiary recover of oil upon recovery of the combined fluids at the surface. The recovered LNG can be commercialized and sold as natural gas, using the existing equipment already in place to distribute oil and gas from the recovery sites to the market.
Further, it is difficult to inject gases into the reservoir, as it requires large high pressure compressors and prime movers at or near the wellbores. It is costly to construct the required compressor injection facilities at each EOR site, and it is even more cost limiting when the EOR site is offshore because the compressors and prime movers would have to be located on the offshore platforms where space is expensive and limited. This present disclosure provides for a solution where these same gases are liquefied as cryogenic liquids prior to injection to the wells, which allows them to be contained in significantly smaller spaces than their gas counterparts because the same volume of the fluid in liquid form contain several orders of magnitude more molecules than when the fluid is in gas form. For example, cryogenic liquefied methane and LNG contains 600 times more methane than an equivalent volume of methane gas. Consequently, a more cost effective method is needed to get large volumes of these cryogenic flood fluids delivered to the EOR sites to be injected into the subterranean oil reservoirs as flood fluids.
Further, currently, the oil and gas industry has many known reservoirs of natural gas that are stranded because the reservoirs are geographically located far from a commercial markets. As such, to commercialize the natural gas, large facilities are built at these stranded geographical areas to liquefied the natural gas produced at these sites. The LNG is transferred to large cryogenic tankers to commercialize the LNG and bring it to a market. The commercial activities, e.g., sales, of the produced cryogenic fluid, LNG, is limited in the world today because the markets for such LNG requires costly cryogenic facilities to receive and or re-gasify the cryogenic liquids at the destination market. These receiving stations at the destination market, or regasification stations, are expensive and require LNG carrying ships to come into ports and near populated areas to discharge their cryogenic cargo. The regasification facilities are often perceived as a potential health hazard; hence, public support for such facilities is difficult to obtain. What is needed are EOR facilities sufficiently far from population centers with facilities and wells equipped to accept the cryogenic fluid cargos as a flood fluid and to serendipitously commercialize the cryogenic flood fluid from production wells once it has served its purpose as a reservoir displacement or flood fluid and is naturally geothermally heated, re-gasified and/or separated from the recovered hydrocarbon produced to surface after the LNG is injected into the subterranean environment and used as the flood fluid.
The present invention provides a method for injecting large volumes of cryogenic liquids into subterranean reservoirs as very cold fluids, which are subsequently extracted from the reservoir with hydrocarbon fluids as a means of enhanced hydrocarbon recovery. As the geothermal energy warms the cryogenic flood fluid the fluid expands causing an increase in pressure in the reservoir. Additionally, the present invention provides a method for creating large conductivity paths for the cold fluids to enter into the reservoir matrix. Furthermore, this invention teaches methods to inject the cold fluid into wells by means of expanding tubular slip joints in the well. In addition, the present invention discloses methods of utilizing the existing equipment to commercialize LNG from stranded locations without having to build additional structures to re-gasify the delivered LNG in natural gas form.